In the petroleum industry, seismic prospecting techniques are commonly used to aid in the search for and the evaluation of subterranean hydrocarbon deposits. The purpose of seismic exploration is to map or image a portion of the subsurface of the earth (a formation) by transmitting energy down into the ground and recording the “reflections” or “echoes” that return from the rock layers below. In general, seismic prospecting consists of three separate stages: data acquisition, data processing and data interpretation. The success of a seismic prospecting operation depends on satisfactory completion of all three stages.
At data acquisition stage, one or more sources of seismic energy emit seismic waves into a subsurface region of interest such as a geologic formation. Seismic exploration typically uses one or more energy sources and typically a large number of sensors or detectors. The sensors that may be used to detect the returning seismic energy are usually geophones (land surveys) or hydrophones (marine surveys). The energy transmitted into the formation is typically sound and shear wave energy. The downward-propagating sound energy may originate from various sources, such as explosions or seismic vibrators on land or air guns in marine environments. Seismic waves enter the formation and may be scattered, e.g., by reflection or refraction, by subsurface seismic reflectors (i.e., interfaces between underground formations having different physical properties). The reflected signals are sampled or measured by one or more detectors, and the resultant data are recorded. The recorded samples may be referred to as seismic data or a set of “seismic traces”. The seismic data may be processed and analyzed to extract details of the structure and properties of the region of the earth being explored.
During a surface seismic survey, the energy source may be positioned at one or more locations near the surface of the earth above a geologic structure or formation of interest, referred to as shotpoints. Each time the source is activated, the source generates a seismic signal that travels downward through the earth and is at least partially reflected from discontinuities of various types in the subsurface, including reflections from “rock layer” boundaries. In general, a partial reflection of seismic signals may occur each time there is a change in the elastic properties of the subsurface materials. Reflected seismic signals are transmitted back to the surface of the earth, where they are recorded as a function of traveltime at a number of locations. The returning signals are digitized and recorded as a function of time (amplitude vs. time).
One prevalent issue with the seismic energy recorded by the detectors during the data acquisition stage is that the seismic traces often contain both the desired seismic reflections (also known as “primary” reflection events or simply “primaries”) and unwanted multiple reflections (also known as “multiples”) which can obscure or overwhelm the primary seismic reflections. A primary reflection is a sound wave that passes from the source to a detector with a single reflection from a subsurface seismic reflector. A multiple reflection is a wave that has reflected at least three times (up, down and back up again) before being received by a detector. Depending on their time delay from the primary events with which they are associated, multiples are commonly characterized as short-path, implying that they interfere with their own primary reflection, or long-path, where they appear as separate events.
There are a variety of types of multiple events. There are signals which are “trapped” in the water layer between two strong reflectors, the free surface and the bottom of the water layer. There are “pegleg” multiple events, which are reflections that are characterized by an additional roundtrip through the water layer just after emission or just before detection. There are “remaining” surface-related multiple events, where the first and last upward reflections are below the first (water) layer, and there is at least one reflection at the free surface in between. There are also “interbed” multiples which have a downward reflection occurring from a subsurface reflector.
In most cases, multiples do not contain useful information that is not more easily extracted from primaries. Moreover, water-bottom multiples have been recognized as a serious noise problem in seismic data processing in many offshore areas. Multiples can severely mask primary reflection events for structural imaging and contaminate amplitude versus offset (“AVO”) information. For these reasons, removal of multiples, or at least attenuation of multiples from the seismic data is an important part of the seismic data processing stage in many environments, particularly in marine settings where multiples are especially strong relative to the primaries. In the case of deep-water data, suppression of first-order and the next few orders of sea-bottom multiple and peg-leg reflections are of great importance. These rather strong multiples may have the same travel time as the primary reflections of target reflectors. In addition to free-surface multiples, interbed multiples have become a more acute problem in many exploration areas where, if mis-interpreted, interbed multiples pose a reservoir characterization challenge in terms of both reservoir structure and AVO effects.
There are prior art methods to attenuate surface-related multiples depending on the attributes of the multiples utilized for attenuation. One class of multiple attenuation method consists of the predictive methods where the multiples are predicted from their respective primaries. The prior art predictive multiple attenuation techniques can be generally divided into two categories: (i) model-driven methods and (ii) data-driven methods. Model-driven methods generally use an earth model in addition to the recorded data to predict or simulate multiples utilizing the estimated sea-bottom and sea-surface reflectivity functions and calculated amplitude functions to model water-layer multiple reflections. Those predicted multiples are then subtracted from the original data. Data-driven methods exploit the fact that primaries and multiples are physically related through a convolutional relationship and predict multiples by crossconvolving the relevant primaries thought to contain the stationary phase contributions for multiples. Data-driven methods can generally handle complex geometries and need little or no a priori information about the properties of the subsurface. Model-driven methods are typically computationally cost-effective compared to data-driven methods, while the latter are typically more flexible and requires less analysis and effort by the user.
Some model-driven methods require structural information, i.e., information about the subsurface structure, the determination of which region is the target of doing seismic exploration in the first place. Other model-driven methods require the shape of the source wavelet that, while impulsive, will not be a mathematically idealized delta function because of the water-bubble reverberations and the limited frequency bandwidth of the physical source. Some model-driven methods require both structural and source wavelet information while others use a matching filter to account for an improperly estimated source wavelet. Data-driven techniques are attractive solutions for predicting multiples in complex geologic settings because they do not require any a priori knowledge of the subsurface (reflectivity, structures and velocities). However, these methods are often too costly because they have strong requirements of the seismic acquisition, e.g., require one shot location for each receiver position, and this is too costly to realize in the field for most three dimensional (“3D”) acquisition geometries.